EFFICIENCY AND COST BENEFIT ASSESSMENTS ON A TYPICAL · energy balanceof the coal fired steam power plant in Figure 4 shows the conversion of electrical power from the 100% chemical

www.tjprc.org SCOPUS Indexed Journal [email protected]

EFFICIENCY AND COST BENEFIT ASSESSMENTS ON A TYPICA L

600MW COAL FIRED BOILER POWER PLANT

THARUN KANTH VENTRAPATI & BOGGARAPU NAGESWARA RAO

Department of Mechanical Engineering, Koneru Lakshmaiah Education Foundation,

Deemed to be University, Green Fields, Vaddeswaram, Guntur, India

ABSTRACT

The overall efficiency of a coal fired boiler power plant ranges from 34 to 40% considering the boiler efficiency

and turbine cycle heat rate. A comparative study is made applying the necessary corrections while evaluating the boiler

efficiency (using the direct and indirect methods) and the turbine cycle heat rate for the design and actual operating

conditions of a typical 600MW coal fired boiler power plant. Heat rate deviation is assessed when the unit in live

operating conditions is deviated from the design operating conditions. Finally, cost benefit and CO2 reduction analyses

are performed fromthe estimated heat rate deviation for abundantly available coals in India. Curative actions and

applicability to conventional and non-conventional fuels, supercritical, combined cycle, nuclear power plants are

highlighted for efficient, economical and eco-friendly operation of the plant.

KEYWORDS: Coal Fired Boiler, Cost Benefit, Direct Method, Efficiency, Heat Rate Deviation; Indirect Method, Power

Plant & Turbine Cycle Heat Rate

Received: Nov 22, 2018; Accepted: Dec 12, 2018; Published: Jan 05, 2019; Paper Id.: IJMPERDFEB201920

1. INTRODUCTION

Power plants play a major role in the country’s economic growth. In developed countries the individual

power consumption is very high (12071kwh/year in USA) when compared to that of developing countries

(1122kWh/year in India)[https://www.cia.gov/library/publications/the-world-factbook/rankorder/2233rank.html].

This is mainly due to high power consumption in industries. Less power consumption indicates low growth in

industries and less job opportunities. India has developed from 1362MW(in 1947at its independence) to

3,43,899MW (in June 2018 having contributions:58% Coal, 20% renewable, 13% hydro, 7% gas, 1.8% Nuclear,

0.2% Oil)[https://powermin.nic.in/en/content/power-sector-glance-all-india/]. In the present scenario 65% of

electricity is generated from thermal power plants utilizing more than 80% of coal in india. For economical

operation there is a need to improve the efficiency of power plants. It is noted that 80% of the commissioned power

capacity is between 210 to 660MW; and theuneconomical operations of old units of 25 to 300MW are to be

scraped [https://npp.gov.in/public-reports/cea/daily/dgr/22-08-2018/dgr1-2018-08-22.pdf]. However, 500 to

660MWunits are producing more than half of the power required in India. Cost benefit analysis on power plants

indicatesa reductionof heat rate deviation which decreases operating costs, coal consumption, CO2 emissions and

improves overall efficiency [1-3]

Original A

rticle International Journal of Mechanical and Production Engineering Research and Development (IJMPERD) ISSN(P): 2249-6890; ISSN(E): 2249-8001 Vol. 9, Issue 1, Feb 2019, 201-216 © TJPRC Pvt. Ltd.

202 Tharun Kanth Ventrapati & Boggarapu Nageswara Rao

Impact Factor (JCC): 7.6197 SCOPUS Indexed Journal NAAS Rating: 3.11

1.1 Operations in a Coal Fired Boiler Thermal Power Plants

Figure 1: A Typical Coal Fired Thermal Power Plant System

Figure 1 shows a typical thermal power plant operating with coal as a fuel. The coal handling plant transfers coal

through belt conveyor to coal hopper, then it supplies to a coal mill through conveyor. A coal mill pulverizes the coal to

fine powder. The air supplied from primary air fan forces this pulverized coal to the boiler through burner system. Forced

draft fan pumps, airinto boiler cavity through windbox. The fuel gun in the burner system makes the air and coal mixture

burn through a chemical reaction producing heat and combustion products (flue gases and ash). The heat produced is

absorbed by water supplied from a boiler feed pump. Water runs through waterwall tubes and converts to steam. Water and

steam mixture enter the boiler drum. The steam from boiler drum enters into super heater coils and goes to the high

pressure turbine (HPT) through main steam line (MS). The steam is partly expanded in HP turbine to avoid formation of

water vapour. This water is reheated in the boiler re-heater coils and goes to intermediate pressure turbine(IPT) through hot

reheat line(HRH) and then expands in IP turbine and low pressure turbine (LPT) and power is produced. The exhaust

steam from the low pressure turbine is condensed to water in condenser using cooling water. The heated up cooling water

is cooled down by a cooling tower and is recirculated by cooling water pump. The condensed steam from LP turbine is

pumped by condensate extraction pump through low pressure heaters which pre-heats the water by extraction steam from

LP turbine. The pre-heated water is supplied through de-aerator to boiler feed pump for raising its pressure. The high

pressure water is further heated by extracting steam from IP turbine and HP turbine in high pressure heaters and then enters

the boiler.

1.2 Unit Operating Conditions

Table 1: Main Operating Conditions of a Typical 600MW Thermal Plant

Main Operating Conditions

Power Output (MW)

Main Steam Cold Reheat Hot Reheat Feed Water mi T/h

hi kJ/kg

mi T/h

hi kJ/kg

mi T/h

hi kJ/kg

mi T/h

hi kJ/kg

100% BMCR/ VWO 648 2028 3397 1719 3048 1719 3534 2028 1236 100% TMCR 600 1849 3397 1576 3033 1576 3537 1849 1206 3% Make Up Water 600 1865 3397 1581 3033 1581 3537 1865 1207 TRIAL RUN 600 1902 3397 1611 3036 1611 3536 1902 1214 80% TMCR 480 1465 3418 1465 3048 1267 3544 1465 1140 60% TMCR 360 1123 3451 1123 3085 0984 3523 1123 1069 50% TMCR 300 0957 3466 0957 3102 0845 3498 0957 1028

Efficiency and Cost Benefit Assessments on a Typical 203 600mw Coal Fired Boiler Power Plant


Table 1: Contd., 40% TMCR 240 0793 3471 0793 3111 0704 3468 0793 0980 All HP heaters bypassed

600 1619 3397 1619 3054 1592 3536 1619 0769

NO.1 HP heater bypassed

600 1751 3397 1751 3041 1607 3536 1751 1065

Extraction Steam 600 1997 3397 1997 3030 1599 3537 1997 1221 Live Near 100% TMCR

576 1798 3392 1552 3046 1552 3515 1728 1221

To achieve the maximum possible efficiency the power plant needs a specification of operating conditions

through experimental trials on a replica module or similar model in a controlled laboratory or the data from the running or

live operating power plants. Data of pressure, temperature, flow rates etc. Guides a power plant to operate in the most

effective manner. The design operating conditions are classified on the boiler rated capacity, turbine rated capacity, load

applied by power grid, feed water heaters conditionand co-generation.

Table 2: Ultimate Analysis Report on Various Types of Coal

Type of Coal Design Coal

Indian Lignite Coal

Semi-Bituminous

Coal

Bituminous Coal

Worst Coal

GCV (Kcal/kg) 3500 4300 4410 5800 3140 Carbon (%) 35.64 37 43.81 59 32.2 Hydrogen (%) 2.48 2.9 2.92 3.1 2.32 Nitrogen (%) 0.68 1.1 1.45 1.1 0.65 Oxygen (%) 5.7 4.5 11.9 10.4 7.33 Sulphur (%) 0.5 1.5 0.02 1.4 0.5 Moisture (%) 10 17 10.75 12.9 12 Ash (%) 45 36 29.15 12.1 45

Figure 2: Types of Coal and Mining Depth

When a boiler operates at its maximum ratecapacity, itit is called 100%BMCR or V. O. All valves of the turbine

are to be fully opened to generate more power than its rated capacity. Similarily when a turbine operates at its maximum

rated capacity it called 100%TMCR (600MW). The grid load on the plant varies seasonally. During the summer the grid

load is maximized and the plant operates at 100%BMCR. When the grid load equals the turbine maximum rated capacity,

it is full load (600MW). When the grid has 40%load the turbine operates at 40% and its rated power is 240MW. When the

grid load is above 100%BMCR it overloads plant system. When it falls below 40%TMCR, efficient and economical

operations of the plant are not possible. When high pressure feed water heaters underperform or malfunction then plant

shall operate by hp heaters bypassed. Also, whensome of the steam is extracted from turbine system for supply to other

units or for co-generation then extraction steam condition occurs. The main operating conditions of a typical 600MW



power plant are presented in Table 1. The ultimate analysis report of Table 2 and Figure 2 on different types of coal helps

the plant operator to opt fuels close to the design fuel. The boiler efficiency and turbine heat rate for operating conditions

in Table 1 with the type of fuel in Table 2 can have 60 multiple values.

Figure 3: Schematic of a Typical 600MW Boiler with Semi-Bituminous Coal as Pulverized Fuel

A schematic of a typical 600MW boiler with semi-bituminous coal as pulverized fuel is shown in Figure 3. The

energy balanceof the coal fired steam power plant in Figure 4 shows the conversion of electrical power from the 100%

chemical energy of design coal. The mechanical losses of steam turbine are found to be negligible.

Figure 4: Energy Balance for Coal Fired Steam Power Plant with Design Coal Flow 376.9T/h



1.3 Objectives of the Present Study

In this paper a comparative study is made initially on the boiler efficiency using direct and indirect methods

taking design coal as reference. The turbine cycle heat rate is evaluated atthe 100% TMCR conditionby dividing the heat

input to steam bya boilerwitha net turbine power output. Turbine cycle heat rate is divided by boiler efficiency to estimate

the unit heat rate. The overall efficiency of the plant is found by dividing the ideal unit heat rate of 860kcal/kWh

withassessedunit heat rate. Heat rate deviation for live operating plant is found by applying the necessary correction factors

and estimated the cost of heat rate deviation and increase in CO2 production. Curative actions are proposed for reduction of

plant heat rate and CO2considering various types of coal in India. This paper highlights on the applicability of various

carbon compound fuel powered plants, combined cycle power plant consisting steam and gas turbines, nuclear power

plants.

2. BOILER EFFICIENCY

Direct method (input-output method) and indirect method (energy balance method)[4] are being used for

evaluation of the boiler efficiency. In direct method, the boiler efficiency ( ηboiler) is the ratio of energy absorbed by fluid

flowing through boiler(output) to the chemical energy of the fuel (input):

ηboiler=mFW( hMS - hFW)+mCRH(hHRH-hCRH)

mCoal ×GCVCoal ×100 (1)

Indirect method for efficiency evaluationrequires chemical analysis of fuel, mass flow rates, temperatures and

pressures of involving parameters. This method estimates boiler efficiency (%) by deducting %heat losses and

superimposing %credits from 100%.

ηboiler= �1-�Energylosses-Energycredits�

Energyinput� ×100 (2)

Srinivas et al. [1] have hinted that boiler efficiency by the direct method is simple but unable to provide the plant

operators about the root cause of lowering the efficiency of the system, which may sometimes mislead. In such a situation,

indirect method (heat balance method/energy balance method) seems to be reliable.

The boiler efficiency by direct method for live plant near 100%TMCR with semi-bituminous coal with GCV of

4410kcal/kg or 18433.8kJ/kg is worked out to be 90.55%. For the design coal flow of 354.29 T/h, the boiler efficiency of

87.87% is taken as reference in the cost benefit and CO2 reduction analyses for coals in Table 2. Boiler efficiency is

evaluated and presented in Table 3. Evaluation of boiler efficiency by indirect method requires the results ofpsychometric

analysis, fuel ultimate analysis, flue gas analysis, ash analysis, boiler and equipment design specifications. Figure 3gives

the data for a live operating plant operating near 100%TMCR with semi-bituminous coal. As per ASME PTC 4 [4], heat

balance method provides the boiler efficiency by considering various percentage heat losses and credits. Sinivas et al. [1]

and Nag [5] have presented formulae for various heat losses. The additional losses introduced in

[https://www.scribd.com/document/253990874/Power-Plant-Commissioning-pdf] are as follows.

Heat loss due toIncomplete combustion=�mdfg×COppm×10-6×GCVCO

GCVCoal×100� (3)

Heat loss due to unburnt carbon in fly ash =BA%×Ash%×CarbonBA% ×GCVCarbon

GCVCoal×100 (4)

206

Impact Factor (JCC): 7.6197

Heat loss due to unburnt carbonin

Sensible heat loss due to fly ash

Sensible heat loss due to bottom ash

Figure 5: Mass Balance for 1 Kg of Semi

When complete combustion takes place,

mass of the dry flue gases (mdfg) is the

Oxygen) excluding water vapour (see Figure

oxides (NOx) and Acid causing substance like SOx

very high combustion temperatures above 1

water vapour [6]. Mass of dry flue gases can be

combustion products [https://beeindia.gov.in/sites/default/files/4Ch1.pdf

Various heat losses accounted in the boiler efficiency eval

Theoritical Air required, TAR=

Excess Air Supplied, EA=35.05%

Actual Air Supplied, AAS=7.54 kg/kg of fuel

Mass of the dry flue gasses, mdfg

Heat loss due to dry flue gases:

Heat loss due to moisture formed from H2 present in fuel:

Heat loss due to moisture in fuel:

Tharun Kanth Ventrapati & Boggarapu Nageswara Rao

SCOPUS Indexed Journal

Heat loss due to unburnt carboninbottom ash = FA%×Ash%×CarbonFA%×GCVCarbon

GCVCoal×100

due to fly ash= �FA%×Ash%×CP(FA)×(TFA-Ta)

GCVCoal×100�

bottom ash= �BA%×Ash%×CP(BA)×(TFA-Ta)

GCVCoal×100�

Figure 5: Mass Balance for 1 Kg of Semi-Bituminous Coal Burnt

takes place, water vapour, ash and dry flue gases become combustion products

sum of the mass of combustion gases (Carbon dioxide, Sulphur dioxide, Nitrogen,

Figure 5). But when incomplete combustion takes place

oxides (NOx) and Acid causing substance like SOx are present. CO is present due to less supply of oxygen

above 1100oC and Sulphuric acid from SOx is due to less dispersion space and high

ass of dry flue gases can be computed by neglecting water vapour present and mass of solid

https://beeindia.gov.in/sites/default/files/4Ch1.pdf].

accounted in the boiler efficiency evaluation are presented below

TAR=5.58 kg/kg of fuel

EA=35.05%

7.54 kg/kg of fuel

dfg= AAS +1= 8.54 kg/kg of fuel

Heat loss due to dry flue gases: Loss1=3.96%

Heat loss due to moisture formed from H2 present in fuel: Loss2=3.73%

Heat loss due to moisture in fuel: Loss3=1.53%

Tharun Kanth Ventrapati & Boggarapu Nageswara Rao

NAAS Rating: 3.11

(5)

(6)

(7)

Bituminous Coal Burnt

become combustion products. The

sum of the mass of combustion gases (Carbon dioxide, Sulphur dioxide, Nitrogen,

takes place Carbon monoxide, Nitrous

. CO is present due to less supply of oxygen. NOx is due to

due to less dispersion space and high

by neglecting water vapour present and mass of solid

below



Heat loss due to moisture presesnt in air: Loss4=0.06%

Heat loss due to incomplete combustion: Loss5=0.02%

Heat loss due to unburnt carbon in bottom ash: Loss6=0.15%

Heat loss due to unburnt carbon in fly ash: Loss7=0.16%

Heat loss due to sensible heat in bottom ash: Loss8=0.1%

Heat loss due to sensible heat in fly ash: Loss9=0.22%

Heat loss due to convection and radiation from asme ptc 4.1 amba curve: Loss10=0.16%

Heat credit due to dry air entering the boiler =0.38%

Heat credit due to moisture in entering air =0.01%

Heat credit due to sensible heat in fuel=0.01

Heat credit due to coal mill=0.19%

Heat credit due to seal air fan=0.01%

Net heat credits=0.6%

�� = 100% − ∑ �� + Net heat credits = 90.56% (8)

Table 3: Boiler Efficiency for Various Types of Coal Near 100%TMCR Live Operating Condition

Description Design Coal

Semi-Bituminous

Coal

Bituminous Coal

Lignite Coal

Worst Coal

Fuel Consumption (T/h) 354.29 276.93 207.46 286.92 399.11 TAR (kg/kg) 4.77 5.58 7.53 5.17 4.25 EA (kg/kg) 35.05 35.05 35.05 35.05 35.05 AAS (kg/kg) 6.44 7.54 10.17 6.98 5.73 LOSS1 (%) 4.35 3.96 3.94 3.79 4.38 LOSS2(%) 3.99 3.73 3.01 3.80 4.16 LOSS3 (%) 1.79 1.53 1.39 2.47 2.39 LOSS4 (%) 0.06 0.06 0.06 0.05 0.06 LOSS5 (%) 0.02 0.02 0.02 0.02 0.02 LOSS6 (%) 0.29 0.15 0.05 0.19 0.32 LOSS7(%) 0.31 0.16 0.05 0.20 0.34 LOSS8(%) 0.1 0.1 0.02 0.1 0.1 LOSS9(%) 0.39 0.22 0.06 0.25 0.43 LOSS10(%) 0.16 0.16 0.16 0.16 0.16 Credits (%) 0.6 0.6 0.6 0.6 0.6 Boiler Efficiency (%) 89.12 90.55 91.84 89.57 88.18

With inclusion of net heat credits, the boiler efficiency evaluated by the indirect method closely matches with that

of the direct method. Considering the same ambient conditions, flue gas analyser report, fly ash and bottom ash conditions

as in Figure 3and specifying thefuel consumption rate and the data of ultimate analysis report in Table 2,the boiler

efficiencyisevaluated for various types of coal and presented in Table 3. Usage of bituminous coal leads to higher boiler

efficiency.



Table 4: Expressions for the Boiler Efficiency Correction

Variable ( x ) ξ Correction ( fC )

Moisture in coal (%),x∈ [5,15] 2.02815-0.202088x 0.0478ξ2 - 0.9508ξ + 0.0015

Hydrogen in (%), x∈ [1,5] 1.68056-0.540476x -0.369ξ2 - 2.4963ξ + 0.8754

Air absolute Humidity (%), x∈ [0.015,0.045] 2.00938-67.0464x -0.1258ξ - 0.0002 Air inlet temperature at Air-heater (0C),x∈ [21,62] 2.00519-0.0483254x -0.0152ξ

2 - 0.6686ξ + 0.007 Feed Water Inlet temperature (0C), x∈ [220,324] 5.22058-0.0191613x 0.2708ξ

2 - 0.6249ξ - 0.038 Ash in Coal (%), x∈ [30,62] 2.78071-0.0610689x 0.0114ξ

2 - 0.0828ξ + 0.0026 HHV of Coal(kcal/kg), x∈ [3164,3824] -10.0262+0.0028634x 0.0389ξ

2 - 0.3648ξ - 0.0051

When live operating conditions (feed water inlet temperature, ambient conditions, fuel/flue-gas/ash chemical

composition) differ from the design operating conditions (100%TMCR with design coal), the necessary corrections to

boiler efficiency are made for moisture in coal, hydrogen in coal, air absolute humidity, air temperature at the air heater

entrance, feed water inlet temperature, ash percentage in coal and heating value of coal from the expressions in Table 4.

Using these expressions, the required corrections are found for the semi-bituminous coal and presented in Table 5. The

corrected boiler efficiency is worked out to be 90.15%.

Table 5: Corrected Boiler Efficiency for Semi-Bituminous Coal

Design Actual Value Corrections (%) Total Moisture in Coal (%) 10 10.75 0.14 H2 in Coal (%) 2.48 2.92 0.6 Air absolute Humidity @60% RH (%) 0.03 0.02 -0.084 Air Temperature at APH inlet (oC) 41.36 25.06 -0.53 Feed Water inlet Temperature (oC) 274.9 277.8 0.03 Ash percentage in Coal (%) 45 29.15 -0.069 Heating Value of Fuel (kcal/kg) 3500 4410 -0.5+

Total -0.40 Corrected Boiler Efficiency (%) 90.15 +HHV maximum Cf=-0.5 when x>>3824

3. CYCLE HEAT RATE AND OVERALL EFFICIENCY

Figure-6: Heat Balance Diagram of a Typical 600 MW Plant Representing Mass Flow Rates

m1 =m’-L1-L2-L3, m2=m1-Ex1-L4-L5-L6, m3=m2-Ex2+L1,m4=m3-Ex3-L7-L8-L9, m5=m4-Ex4+L6+L3, m6=m5-Ex5,m7=m6-Ex6, m8=m7-Ex7, m9=m8-Ex8



Using the heat balance diagram of Figure 6 cycle heat rate and overall efficiency of the unit are estimated. Figure

7shows temperature and entropy. Tables 6 and 7 give the mass flow rate, leakages, temperature, pressure, enthalpy for

main design conditionsand various operating parameters for live operating plant. Heat rate is the energy required to

produce one kWh power. Theoretically 1kWh equals3600kJ. So plant with 100% efficiency will have 3600kJ/kWh or

860kcal/kWh of heat rate. But due to heat losses in boiler,turbine and auxiliaries it is between 7400 to 9400 kJ/kWh[7].

Turbine cycle heat rate (TCHR) is the ratio of heat input to the cycle to the Net power output [8]:

TCHR=Heat input to the Turbine cycle

Net Power Output =

Main Steam Flow �hMS-hFW�+CRH Flow �hHRH-HCRH�Net Power Output

(9)

The net power output (PNet) of turbine is power output times the generator efficiency:

Figure 7: Temperature and Entropy Diagram

(10)

Here P =PHPT+PIPT+PLPT (11)

The power output in HP turbine,

PHPT=.m1�hMS-hEx1�+m2�hEx1-hCRH�. (12)

The power output in IP turbine,

PIPT=m3�hHRH-hEx3�+m4�hEx3-hLPT in� (13)

The power out in LP turbine,

PLPT=m5�hLPT in-hEx5�+m6�hEx5-hEx6�+m7�hEx6-hEx7�+m8(hEx7-hEx8)+m9(hEx8-hLPT Exhaust) (14)

Net generatorP =P×η



Table 6: Desing Operating Parameters at 100%TMCR with Design Coal and Live Operating Parameters Near 100%TMCR with Semi-Bituminous Coal

Using the design data in Table 6 and referring Figure 6, the net power output is evaluated as

PNet=(180.5+152.8+274)×0.988=600MW andTCHR=1931.58kcal

kWh.

Turbine efficiency, unit heat rate (UHR) and overall efficiency are evaluated from[9]

Turbine Efficiency = 860

TCHR×100=44.52% (15)

Unit heat rate /UHR)=TCHR

Boiler Efficiency=9187.53 kJ/kWh=2198 kcal/kWh (16)

Overall Efficiency = 860

UHR×100=39.12% (17)

Similarily, the overall efficiency is evaluated for the operating conditions of Table 1 and presentedthe results in

Table 7. It is noted that the heat rate is morewhen unit operates at less load or power ouput. Overall efficiency is maximum

when heat rate is minimum. Unit heat rate for extraction steam condition is minimum and is similar to cogeneration.

Table 7: Power Output and TCHR, UHR, Overall Efficiency at Main Operating Conditions

Description (See Figure

6) UOM

TMCR with 3% Make Up

VWO 80%

TMCR 40%

TMCR

ALL HP Heaters

Out

No.1 HP heater Out of Service

Extraction Steam

Condition

MS T/h 1864.50 2028.00 1465.31 792.71 1618.90 1751.10 1997.10 Prs. /Temp MPa/oC 16.67/538 16.67/538 14.82/538 7.41/527 16.67/538 16.67/538 16.67/538 CRH T/h 1581.09 1718.94 1266.83 704.14 1591.64 1606.92 1598.86 Prs. /Temp MPa/oC 3.8/324 4.13/333 3.07/322 1.68/335 3.94/333 3.87/327 3.82/323 HRH T/h 1581.09 1718.94 1266.83 704.14 1591.64 1606.92 1598.86 Prs. /Temp MPa/oC 3.42/538 3.72/538 2.76/538 1.51/498 3.55/538 3.48/538 3.43/538 FW T/h 1864.50 2028.00 1465.31 792.71 1618.90 1751.10 1997.10 Prs. /Temp MPa/oC 18.66/275 18.66/281 16.81/261 9.4/228 18.66/183 18.66/245 18.66/278 Ext 1 T/h 137.01 150.66 93.56 40.45 0.00 0.00 213.87 Prs. /Temp MPa/oC 6.12/389 6.67/399 4.91/385 2.74/401 6/391 6.23/393 3.82/323 Ext 2 T/h 117.50 127.07 82.04 35.87 0.00 115.86 154.22 Prs. /Temp MPa/oC 3.8/324 4.13/333 3.07/322 1.68/335 3.94/333 3.87/327 6.37/393



Ext 3 T/h 95.30 102.64 68.31 33.25 0.00 93.76 104.58 Prs. /Temp MPa/oC 2.17/469 2.36/469 1.76/471 0.97/435 2.33/475 2.21/470 2.15/468 Ext-4 T/h 166.77 177.34 120.58 49.10 166.02 161.51 252.32 Prs. /Temp MPa/oC 1/357 1.09/357 0.82/360 0.46/332 1.08/363 1.02/358 0.93/349 Ext 5 T/h 48.00 51.31 35.38 17.57 50.00 47.19 48.98 Prs. /Temp MPa/oC 0.37/241 0.4/241 0.3/244 0.11/221 0.4/246 0.38/242 0.34/234 Ext 6 T/h 44.79 47.65 33.43 16.72 46.73 44.05 45.45 Prs. /Temp MPa/oC 0.21/182 0.23/182 0.17/185 0.1/165 0.23/186 0.22/183 0.2/175 Ext 7 T/h 46.28 49.61 34.13 16.80 48.07 45.47 47.51 Prs. /Temp MPa/oC 0.21/125 0.13/125 0.1/127 0.06/110 0.13/129 0.12/126 0.11/119 Ext 8 T/h 78.05 86.74 53.14 18.03 84.27 77.95 76.72 Prs. /Temp MPa/oC 0.06/85 0.06/87 0.05/80 0.03/68 0.06/87 0.06/85 0.05/83 IPT to LPT T/h 1342.25 1464.12 1096.23 631.54 1446.81 1374.19 1266.74 Prs. /Temp MPa/oC 0.98/357 1.07/357 0.81/360 0.46/332 1.06/363 1.01/358 0.92/349 LPT exhaust T/h 1126.79 1230.47 941.79 564.08 1219.40 1161.18 1049.74 Enthalpy kJ/kg 2.38 2.37 2.42 2.52 2.38 2.38 2.39 Total Gland Leakage

T/h 22.00 24.00 17.00 11.00 22.00 22.00 22.00

Power Output (MWh) 600.2 648.6 480.1 240.0 600.0 600.1 605.7 TCHR (kJ/kWh) 8034.1 8055.9 8262.4 9272.1 8321.3 8133.8 7695.7 UHR (kJ/kWh) 9142.2 9166.9 9402.0 10550.8 9468.9 9255.6 8757.1 Overall Efficiency (%) 39.3 39.2 38.2 34.1 38.0 38.8 41.1

Cost per unit power produced is [3, 7]

Cost Per kWh=TCHR

ηboiler×Cost of Coal per kcal (18)

4. HEAT RATE DEVIATION

When thermal performance parameters of the unit deviate from the main operating conditions, their influence on

the unit heat rate (UHR) can be found using the heat rate deviation method [https://www.scribd.com/document/379461735/4-

EEMS]. As in [9] correction factors for the 600MW turbine are provided in Table 8

Corrected Heat Rate= Heat Rate/1+Cf

100)0 (19)

Table 8: Expressions for the Unit Heat Rate Correction

Variable ( x ) ξ Correction ( fC )

Main Steam Pressure (MPa), x∈ [15, 18] -13.3903+0.815262x 0.0844ξ2 - 0.8359ξ + 0.1657 Main Steam temp (0C), x∈ [522, 549] -37.4137+0.0699032x -0.3821ξ + 0.0762 Reheater Pressure Drop (MPa), x∈ [7, 12] -35.5767+0.0663746x -0.4018ξ + 0.0555 Reheat temperature(0C), x∈ [522, 552] -3.82108+0.402317x 0.2407ξ - 0.0445 Condenser Back pressure (kPa), x∈ [5.3, 14.7] -2.12746+0.213783x 0.3411ξ2 + 3.2634ξ + 0.3864 BFPT Steam Flow (T/h), x∈ [32.75, 34] 31.7498-0.950661x -0.0011ξ2 - 0.0892ξ + 0.0592 SH spray ratio, x∈ [0, 8] -1+0.248437x -0.104ξ2 + 1.115ξ + 1.199 HPH TD (0C), x∈ [-3,1.6] -0.200787-0.40058x -0.0451ξ + 0.0232 HPH DC (0C), x∈ [2,10] 1.49894-0.250073x -0.0078ξ + 0.0008 Control Valve#3 open (%), x∈ [32,100] -1.86883+0.0286883x -0.1813ξ2 - 0.1942ξ + 0.3784 Control Valve#4 open (%), x∈ [0,48] -1.04251+0.0423932x -0.0651ξ2 + 0.1486ξ + 0.2148



Table 9: Cost of Heat Rate Deviation for Live Operating Plant near 100%TMCR

Description (see Figure 6)

Design Actual Correction Factor, Cf

Corrected UHR+

Heat Rate Deviation++

Cost of Heat Rate Deviation

(Crores.) Throttle pressure, MPa 16.67 16.11 0.39 2189 9.2 1.04 Throttle temperature, oC 538 533.12 0.13 2195 2.9 0.35 RH Temp. oC 538 527.74 0.28 2192 6.1 0.75 RH pressure drop % 10 9.45 -0.05 2199 -1.1 -0.13 Condenser pressure. Kpa 9.4 10.8 0.99 2174 23.9 2.63 Spray water flow ratio 0 6.11 1.75 2161 36.7 4.61 RH spray flow. Ratio 0 0 0 2198 0.0 - Make up flow, T/h 0 0 0 2198 0.0 - Valve position, CV1-3 100 100 0 2198 0.0 - Valve position, CV4 0 30.65 0.25 2193 5.5 0.67 Speed, rpm 3000 2998.2 0 2198 0.0 - HP heater TD, oC -1.7 -1.2 0.01 2198 0.2 0.03 HP heater DC. oC 5.6 29 0.01+++ 2198 0.2 0.03 Condenser sub cooling, oC 0 0 0 2198 0.0 - TDBFP steam flow, T/h 32.7 32.63 -0.01 2198 -0.2 -0.03 Unit aging, month 10 10 0.5 2187 10.9 1.34 Cost Reduction per annum(Crores.) 92.4 11.28 +Corrected UHR, CUHR= UHR/(1+Cf/100) ++ Heat rate deviation= UHR-CUHR +++HP heater DC maximum possible Cf=0.01 when x>>10

Using the design and live plant parameters of Table 6 and correction factors in Table 8, the heat rate deviation

calculated in Table 9 is 92.4. Throttle pressure andtemperature in Table 9 indicate the main steam pressure andtemperature

at inlet to HP turbine. RH temperature andpressure indicate the hot reheat temperature inlet to IP turbine. Pressure drop due

to reheating of CRH (cold reheat) to HRH (hot reheat) can be found from

Reheat Pressure Drop=100-CRH pressure

HRH pressure×100=100-

3.489

3.853×100=9.45 (20)

SH spray is used to control the temperature and pressure of the main steam line. Using the flow of super heater

spray(110T/h) and themain steam flow (1798.85T/h), one can obtain

Spray water flow ratio (%)=SH spreay flow

Main steam flow×100=

110

1798.85×100=6.11 (21)

Using the flow of re-heater spray (0 T/h) andhot reheat flow (1527 T/h),one can obtain

RH spray flow ratio (%)= RH spray flow

Reheat steam flow×100=0 (22)

The de-mineralized water is added to the plant cycle due to water and steam leakages. Generally 3% make-up

water is added, which is 3% of Throttle Flow (= 3%×1798.85=53.96 T/h ). Control valve (CV) position indicates the

percentage opening of 4 control valves on HP turbine. In general first 3 control valves (CV1, CV2, CV3) are fully open in

most conditions, whereas CV4fully opens only in 100% BMCR or VWO condition. Figure 8 shows thermal profile of feed

water heater.

Efficiency and Cost Benefit Assessments on a Typical 600mw Coal Fired Boiler Power Plant

www.tjprc.org

Figure 8: Feed Water Heater Thermal

Heater TD=Tsat-TFw/out),

is the temperature difference between

water outlet temperature (TFW(out)).

Heater DC=TDrip-TFw/in),

is the heater drain cooler temperature

inlet temperature (TFW(in)).

When cooling water flow through condenser is higher than

back pressure and reduces heat transfer due

baffle plates. TDBFP or BFPT steam flow indicates the amount of

typical 600MW unit, two numbers of TDBFP are used to pump the feed water after unit start

by motor is kept idle. Usage of TDBFP reduces power consumption,

aging is counted from the time when unit ac

bituminous coal is Rs.1024/ton [https://www.coalindia.in/

Fuel Cost=Cost of Coal per kg

GCVCoal=0.000232

Cost of heat rate deviation per annum

= 92.4 1 600000 1 24 1 365 1Plant load factor (PLF)is taken as

of heat rate deviation for live operating unit near 100%TMCR for different types of coals in India.

deviation is found to be minimum for Indian lignite coal due to low fuel cost and reasonably high GCV value.

Table 10:

Description

GGV of coal (Kcal/Kg) Coal cost per ton (Rs.) Coal cost per Kcal (Rs.)

Efficiency and Cost Benefit Assessments on a Typical

SCOPUS Indexed Journal

Figure 8: Feed Water Heater Thermal Profile

ifference between extraction steam saturation temperature (Tsat

emperature difference between heater drain outlet temperature

ater flow through condenser is higher than its design,condenser sub

ack pressure and reduces heat transfer due to formation of water droplets and air bubbles on

steam flow indicates the amount of steam flow to turbine d

of TDBFP are used to pump the feed water after unit start

e of TDBFP reduces power consumption, and can have safe and

unit achievessynchronization mile stone (i.e. Turbine runs at 3000rpm)

https://www.coalindia.in/].

000232Rs.

kcal

Cost of heat rate deviation per annum= Heat rate deviation×net generation×fuel cost×plant load factor

1 0.000232 1 1= 11,28,00,927 Rs.≈ 11.28 crores

taken as unity assuming 100% load on the plant through the year

of heat rate deviation for live operating unit near 100%TMCR for different types of coals in India.


Table 10: Cost of Heat Rate Deviation for Live Operating Unit near 100% TMCR for Various Coals

Design Coal

Semi-Bituminous

Coal

Bituminous Coal

Indian Lignite Coal

3500 4410 5800 4300817 1024 2317 955

0.0233 0.0232 0.03995 0.02221

213

[email protected]

(23)

sat) at inlet pressure and thefeed

(24)

ifference between heater drain outlet temperature (TDrip) and feed water

ub-cooling increases condenser

on condenser tube bundle and

driven boiler feed pump. In a

of TDBFP are used to pump the feed water after unit start-up. Boiler feed pump driven

and flexibility operations. Unit

tone (i.e. Turbine runs at 3000rpm). Cost of semi-

(25)

Heat rate deviation×net generation×fuel cost×plant load factor

assuming 100% load on the plant through the year. Table 10 givesthe cost

of heat rate deviation for live operating unit near 100%TMCR for different types of coals in India. The cost of heat rate


Indian Lignite Coal

Worst Coal

4300 3140 955 748

0.02221 0.02382



Heat rate deviation (Kcal/kWh) 92.43 92.43 92.43 92.43 92.43 Cost (Crores) 11.34 11.28 19.41 10.79 11.57

Increase in coal input per annum=Cost of Heat Rate Deviation per annum

Coal cost per ton= 11,28,00,927 /1024= 1,10,157 tons

CO2produced per kg of fuel=%C in fuel×molecular weight of CO2atomic weight of Carbon

= 0.43811 44

12= 1.6064kg/kg of fuel

Increase in CO2 per annum=Increase in Coal input per annum×CO2 produced of ton coal

= 1,10,1571 1.6064 Ton = 1,76,953 Ton per annum

Table 11 gives the possible CO2reduction for live operating unit near 100% TMCR forvarious coals. When carbon

in coal completely burns it converts to CO2.CO and CO2 are produced when incomplete combustion takes place.

CO produced per kg of fuel=mdfg×CO in ppm×10-6 = 7.441 401 1036 = 0.000297 Kg/Kg of fuel

Since the carbon monoxide produced is very less compared to that of CO2and hence, it is neglected.

Similarily,cost of heat rate deviation iscalculated for the coals in Table 2 and the operating parameters of Table 8.

Table 11: Possible CO2 Reduction for Live Operating Unit near 100% TMCR

Description Design Coal

Semi-Bituminous Coal

Bituminous Coal

Lignite Coal Worst Coal

GCV(Kcal/kg) 3500 4410 5800 4300 3140 Carbon (%) 35.64 43.81 59 37 32.2 Coal cost per ton (Rs.) 817 1024 2317 955 748 Cost of heat rate deviation (Cr./year)

11.34 11.28 19.41 10.79 11.57

Coal wasted per annum (Tons)

1,38,798 1,10,157 83,757 1,12,975 1,54,711

CO2 produced per kg coal 1.31 1.61 2.16 1.36 1.18 CO2 reduction per annum (Ton)

1,81,381 1,76,953 1,81,195 1,53,270 1,82,662

5. OTHER APPLICATIONS

In combined cycle power plant unit heat rate is the ratio of heat input in a gas turbine to the gross power output of

gas & steam turbines, power output & heat rate deviation procedures for steam turbine part remain same. The overall

efficiency of combined cycle plant is above 48%. The power output of gas turbine and efficiency of the Heat recovery

steam generator can be evaluated as per ASME PTC 4.4 [10].

In cogeneration for evaluation of the unit heat rate, the heat carried away by the process steam is to be deducted

from heat input to the cycle while adding heat input by make-up water for all power plants, which decreases net heat input.

The decrease net heat input leads to decrease in the unit heat rate and increase in overall efficiency.

In a nuclear power plant the boiler in coal fired steam power plant is replaced with a nuclear reactor. The reactor

has 13% energy loss due to radiation and circulation loss, whereas49% energy loss in steam turbine and condenser. when

reactor efficiency is given It should be noted that the overall efficiency and the unit heat rate evaluation procedures are

same for super critical/ultra mega power projects. When changes take place in the fuel input to the power plant, its furnace

size and combustion mechanism in burner system are to be changed accordingly. Fluidized bed combustion is preferred



against pulverized fuel wall firing for the fuels having high percentage of solid waste products

[http://drtlud.com/BEF/proximat.htm].

6. CONCLUSIONS

The overall plant efficiency is found to increase with the decreasingunit heat rate (UHR). The cost per kWh is also

decreased. For less UHR, the cost of heat rate deviation can be minimized for highmain steam throttle temperature and

pressure. Superheat spray and reheater spray water utilization need to be minimized or to be avoided. Condenser back

pressure need to be maintained below 9.4kPa to achieve the cost saving of 11.3crores per annum. Also this cost per annum

can be minimizedthrough lowcost coal having highGCV. CO2 Production can also be minimized using coal having high

GCV and less Carbon Content as in lignitecoal. As the efficiency of combined cycle plant is high when compared to coal

fired boiler power plant, coal gasification is preferred instead of direct coal firing. The fuel from coal gasification can be

used in combined cycle plants, which minimizes environmental pollution due to ash absent in the combustion products.

REFERENCES

1. G. T. Srinivas, D. Rajeev Kumar, V. Peruri, V. Murali, and B. Nageswara Rao, “Efficiency of a Coal Fired Boiler in a Typical

Thermal Power Plant,” AJMIE, vol. 2, no. 1, pp. 32–36, 2017.

2. M. Blessy Raisa and B. Nageswara Rao, “Performance of AFBC and CFBC boilers in thermal power plants,” Int. J. Control

Theory Appl., vol. 10, no. 10, pp. 83–89, 2017.

3. Palo and S. Korellis, “Range and Applicability of Heat Rate Improvements,” California, 2014.

4. Fired Steam Generators: Performance Test Codes, ASME PTC 4-2013.

5. P. K. Nag, Power Plant Engineering, 4th Edition, McGraw-Hill Education (India) Private Limited, 2015.

6. E. Krawczyk and M. Zajemska, “The chemical mechanism of SOx formation and elimination in coal combustion process,”

CHEMIK, vol. 67, no. 10, pp. 856–862, 2013.

7. J. Robert Tramel, “Heat rate improvement guidelines for Indian Power Plants,” United States Tennessee Valley Authority,

Knoxville, Tennessee, 2000.

8. Geete and A. I. Khandwawala, “Thermodynamic analysis of 120 MW thermal power plant with combined effect of constant

inlet pressure (124.61 bar) and different inlet temperatures,” Case Stud. Therm. Eng., vol. 1, no. 1, pp. 17–25, 2013.

9. Pradip and M. Suparna, Operation and Maintenance of Thermal Power Stations, 1st Edition. Noida: Springer, 2016.

10. Gas Turbine Heat Recovery Steam Generators Performance Test Codes, New York: ASME, 2009.

Documents

EFFICIENCY AND COST BENEFIT ASSESSMENTS ON A TYPICAL · energy balanceof the coal fired steam power plant in Figure 4 shows the conversion of electrical power from the 100% chemical